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EX-31.1 - EX-31.1 - Atlas Resources Public #18-2009 (B) L.P.pub18b-ex311_7.htm
EX-31.2 - EX-31.2 - Atlas Resources Public #18-2009 (B) L.P.pub18b-ex312_10.htm
EX-23.1 - EX-23.1 - Atlas Resources Public #18-2009 (B) L.P.pub18b-ex231_222.htm
EX-32.2 - EX-32.2 - Atlas Resources Public #18-2009 (B) L.P.pub18b-ex322_8.htm
EX-32.1 - EX-32.1 - Atlas Resources Public #18-2009 (B) L.P.pub18b-ex321_9.htm
EX-99.1 - EX-99.1 - Atlas Resources Public #18-2009 (B) L.P.pub18b-ex991_223.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015

OR

¨

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______ 

Commission file number: 333-150925-02

 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

26-3223040

(State or other jurisdiction or

incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

Park Place Corporate Center One

1000 Commerce Drive, Suite 400

Pittsburgh, PA

 

15275

(Address of principal executive offices)

 

Zip code

Registrant’s telephone number, including area code: (412) 489-0006

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

None

 

None

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Units representing Limited Partnership Interests

(Title of Class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer    ¨

 

Accelerated filer    ¨

 

Non-accelerated filer    ¨

 

Smaller reporting company    x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

INDEX TO ANNUAL REPORT

ON FORM 10-K

TABLE OF CONTENTS

 

 

 

 

 

 

Page

 

PART I

 

Item 1:

 

Business

7

  

 

 

 

Item 2:

 

 

Properties

20

  

 

 

 

Item 3:

 

 

Legal Proceedings

22

  

 

 

 

Item 4:

 

 

Mine Safety Disclosures (Not Applicable)

22

  

 

PART II

 

 

Item 5:

 

 

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

23

  

 

 

 

Item 7:

 

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

23

  

 

 

 

Item 8:

 

 

Financial Statements and Supplementary Data

32

  

 

 

 

Item 9:

 

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

51

  

 

 

 

Item 9A:

 

 

Controls and Procedures

51

  

 

PART III

 

 

Item 10:

 

 

Directors, Executive Officers and Corporate Governance

52

  

 

 

 

Item 11:

 

 

Executive Compensation

53

  

 

 

 

Item 12:

 

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

53

  

 

 

 

Item 13:

 

 

Certain Relationships and Related Transactions

54

  

 

 

 

Item 14:

 

 

Principal Accountant Fees and Services

54

  

 

PART IV

 

 

Item 15:

 

Exhibits

55

  

 

SIGNATURES

56

  

 

 

 

2


 

GLOSSARY OF TERMS

Bbl. One barrel of crude oil, condensate, or other liquid hydrocarbons equal to 42 United States gallons.

Bpd. Barrels per day.

Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Fractionation. The process used to separate a natural gas liquid stream into its individual components.

GAAP. Generally Accepted Accounting Principles in the United States of America.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbl. One thousand barrels of crude oil, condensate, or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas; the standard unit for measuring volumes of natural gas.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Mcfd. One thousand cubic feet per day.

Mcfed. One Mcfe per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

Natural Gas Liquids or NGLs —A mixture of light hydrocarbons that exist in the gaseous phase at reservoir conditions but are recovered as liquids in gas processing plants. NGL differs from condensate in two principal respects: (1) NGL is extracted and recovered in gas plants rather than lease separators or other lease facilities; and (2) NGL includes very light hydrocarbons (ethane, propane, butanes) as well as the pentanes-plus (the main constituent of condensates).

NYMEX. The New York Mercantile Exchange.

NYSE. The New York Stock Exchange.

Oil. Crude oil and condensate.

Productive well. A producing well or a well that is found to be capable of producing either oil or gas in sufficient quantities to justify completion as an oil and gas well.

Proved developed reserves. Reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved reserves. Proved gas and oil reserves are those quantities of gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.


3


 

(i)

The area of the reservoir considered as proved includes: 

(a)

The area identified by drilling and limited by fluid contacts, if any, and

(b)

Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv)

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(a)

Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(b)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

PV-10. Present value of future net revenues. See the definition of “standardized measure”.


4


 

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

SEC. Securities Exchange Commission.

Standardized Measure. Standardized measure, or standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

Successful well. A well capable of producing gas and/or oil in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas and oil regardless of whether such acreage contains proved reserves.

Working interest. An operating interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and the responsibility to pay royalties and a share of the costs of drilling and production operations under the applicable fiscal terms. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.  For example, the owner of a 100.00% working interest in a lease burdened only by a landowner’s royalty of 12.50% would be required to pay 100.00% of the costs of a well but would be entitled to retain 87.50% of the production.


5


 

FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates, and projections. While we believe these expectations, assumptions, estimates, and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. The following and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

 

·

the demand for natural gas, oil, NGLs and condensate;

 

·

the price volatility of natural gas, oil, NGLs and condensate;

 

·

changes in the differential between benchmark prices for oil and natural gas and wellhead prices that we receive;

 

·

changes in the market price of our common units;

 

·

future financial and operating results;

 

·

resource potential;

 

·

economic conditions and instability in the financial markets;

 

·

the accuracy of estimated natural gas and oil reserves;

 

·

the financial and accounting impact of hedging transactions;

 

·

the limited payment of distributions, or failure to declare a distribution;

 

·

the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations at a reasonable cost and within applicable environmental rules;

 

·

the effects of unexpected operational events and drilling conditions, and other risks associated with drilling operations;

 

·

impact fees and severance taxes;

 

·

changes and potential changes in the regulatory and enforcement environment in the areas in which we conduct business;

 

·

the effects of intense competition in the natural gas and oil industry;

 

·

general market, labor and economic conditions and uncertainties;

 

·

the ability to retain certain key customers;

 

·

dependence on the gathering and transportation facilities of third parties;

 

·

the availability of drilling rigs, equipment and crews;

 

·

potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

 

·

uncertainties with respect to the success of drilling wells at identified drilling locations;

 

·

uncertainty regarding leasing operating expenses, general and administrative expenses and funding and development costs;

 

·

exposure to financial and other liabilities of the managing general partner;

 

·

the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our business and operations;

 

·

restrictions on hydraulic fracturing;

 

·

exposure to new and existing litigation;

 

·

development of alternative energy resources; and

 

·

the effects of a cyber-event or terrorist attack.

 

Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments, except as may be required by law.


6


 

 

PART I.

ITEM 1: BUSINESS

Overview

Atlas Resources Public #18-2009 (B) L.P. (“we, “us” or the “Partnership”) is a Delaware limited partnership and was formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE:ARP). ARP is a publicly traded master limited partnership and an independent developer and producer of natural gas, crude oil, and natural gas liquids, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, in which it co-invests to finance a portion of its natural gas and oil production activities.

 

On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS). Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.

The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee and Indiana. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services. (See Item 11: “Executive Compensation”).

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically.

Historically, there has been no need to borrow funds from the MGP to fund operations as the amount of funds generated by the Partnership’s operations has been adequate to fund future operations and distributions to the partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted, as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s operations for at least the next 12 months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern.

After formation, we received total cash subscriptions from investors of $122,554,200, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $27,065,200. We have drilled 84 development wells within the Marcellus Shale, Southern Appalachia Shale, Antrim Shale, and New Albany geological formations in Pennsylvania, Tennessee, Michigan and Indiana.


7


 

Business Strategy

We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling (See Item 2: “Properties” for information concerning our wells).

The MGP continues to manage our exposure to commodity price risk. To limit our exposure to changing commodity prices and enhance and stabilize our cash flow, our MGP uses financial hedges for a portion of our natural gas production. Principally, the MGP uses fixed price swaps and puts on our behalf as the mechanism for the financial hedging of our commodity prices.

Our operating cash flows are generated from our wells, which produce natural gas and oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The majority of our natural gas is delivered into the Laurel Mountain Midstream, LLC (“Laurel Mountain”) gas gathering system. Our MGP entered into new gas gathering agreements with Laurel Mountain, whereby they pay to Laurel Mountain a gathering fee based on a range, generally from $0.35 per Mcf to the amount of the competitive gathering fee which is currently defined as 16% of the gross sales price received for our gas.

Our ongoing operating and maintenance costs have been or are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We are charged by our MGP a monthly well supervision fee of $975 per well per month for the Marcellus Shale wells, $1,500 per well per month for New Albany Shale wells and for all other wells a fee of $392 is charged per well per month as outlined in our drilling and operating agreement. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

 

 

Well tending, routing maintenance and adjustment;

 

Reading meters, recording production, pumping, maintaining appropriate books and records; and

 

Preparation of reports for us and government agencies.

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment and materials and brine disposal. If these expenses are incurred, we are charged the costs for third-party services, materials and a competitive charge for services performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month per well to cover the estimated future plugging and abandonment cost of the well. As of December 31, 2015, our MGP withheld $69,400 of net production revenue for this purpose.

Gas and Oil Production

Production Volumes

The following table presents our total net natural gas, oil and natural gas liquids production volumes for the years ended December 31, 2015 and 2014:

 

 

Years Ended December 31,

 

 

2015

 

  

2014

 

Production: (1)

 

 

 

  

 

 

 

Natural gas (Mcf)

 

1,359,625

  

  

 

1,653,142

  

Oil (Bbl)

 

24

  

  

 

54

  

Total (Mcfe)

 

1,359,769

  

  

 

1,653,466

  

 

 

(1)

Production quantities consist of the sum of our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells.


8


 

Production Revenues, Prices and Costs

The MGP markets the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are Dominion South Point, Tennessee Gas Pipeline and Transco Leidy Line.

Our production revenues and estimated gas, oil and natural gas liquid reserves are substantially dependent on prevailing market prices for natural gas. The following table presents our production revenues and average sales prices for our natural gas, oil and natural gas liquids production for the years ended December 31, 2015 and 2014, along with our average production costs in each of the reported years:

 

 

Years Ended December 31,

 

 

2015

 

  

2014

 

Production revenues (in thousands):

 

 

 

  

 

 

 

Natural gas revenue

$

2,382

  

  

$

5,542

  

Oil revenue

 

1

  

  

 

5

  

Total revenues

$

2,383

  

  

$

5,547

  

 

Average sales price: (1)

 

 

 

  

 

 

 

Natural gas (per Mcf) (2)

$

1.80

  

  

$

3.46

  

Oil (per Bbl)

$

43.86

  

  

$

89.88

  

 

 

 

 

 

 

 

 

Production costs (per Mcfe)

$

1.24

  

  

$

1.37

  

 

 

(1)

Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

 

(2)

Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $69,200 and $183,300 for the years ended December 31, 2015 and 2014, respectively.

 

Drilling Activity

 

We received total cash subscriptions from investors of $122,554,200, which were paid to our MGP acting as operator and general drilling contractor under our drilling and operating agreement. Our MGP contributed leases, tangible equipment, and paid all syndication and offering costs for a total capital contribution of $27,065,200. We have drilled 84 development wells within the Marcellus Shale, Southern Appalachia Shale, Antrim Shale and New Albany Shale geological formations in Pennsylvania, Tennessee, Michigan and Indiana. We intend to produce our wells until they are depleted or become uneconomical to produce, at which time they will be plugged and abandoned or sold. No other wells will be drilled and no additional funds will be required for drilling. The following table summarizes the number of gross and net wells drilled by the Partnership:

 

 

Gross

 

  

Net

 

Gas wells drilled

 

79.00

 

 

 

52.79

  

Dry hole

 

5.00

 

 

 

4.25

  

Total wells drilled

 

84.00

 

 

 

57.04

  

 


9


 

Natural Gas and Oil Leases

 

The MGP has contributed all the undeveloped leases or lease interests necessary to drill each of the partnership’s wells. The MGP has received a credit to its capital account equal to the cost of each lease or the fair market value of each lease if the MGP has reason to believe that cost is materially more than the fair market value.

 

Contractual Revenue Arrangements

 

Natural Gas. The MGP markets the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically linked to a regional index. The pricing indices for the majority of our production areas are as follows:

 

 

·

Appalachian Basin - Dominion South Point, Tennessee Gas Pipeline Zone 4 (200 Leg), Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5; and

 

·

Other regions - primarily the Texas Gas Zone SL spot market (New Albany Shale) and the Cheyenne Hub spot market (Niobrara). 

 

We attempt to sell the majority of our natural gas at monthly, fixed index prices and a smaller portion at index daily prices.

 

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking/pipeline charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

 

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. The resulting plant residue natural gas is sold as described above and the NGLs are generally priced and sold using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a percentage retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

 

For the year ended December 31, 2015, Chevron Natural Gas and Atmos Energy Marketing, LLC accounted for approximately 81% and 13%, respectively, of our total natural gas, oil, and NGL production revenues, with no other single customer accounting for more than 10% of revenues for this period.

 

Natural Gas Hedging

 

The MGP provides greater stability in our cash flows through its use of financial hedges for our natural gas production. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between ourselves and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us to mitigate hydrocarbon price risk and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with the MGP’s secured credit facility do not require cash margin and are secured by our natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the MGP has a management committee to assure that all financial trading is done in compliance with its hedging policies and procedures. The MGP does not intend to contract for positions that we cannot offset with actual production.


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Natural Gas Gathering Agreements

 

Virtually all natural gas produced is gathered through one or more pipeline systems before sale or delivery to a marketer or an interstate pipeline. A gathering fee can be charged for each gathering activity that is utilized and by each separate gatherer providing the service. Fees will vary depending on the distance the gas travels and whether additional services such as compression, blending, or contaminant removal are provided.

 

In Appalachia, we have gathering agreements with Laurel Mountain Midstream, LLC (“Laurel Mountain”). Under these agreements, we dedicate our natural gas production in certain areas within southwest Pennsylvania to Laurel Mountain for transportation to interstate pipeline systems or local distribution companies, subject to certain exceptions. In return, Laurel Mountain is required to accept and transport our dedicated natural gas subject to certain conditions. The greater of $0.35 per mcf or 16% of the gross sales price of the natural gas is charged by Laurel Mountain for the majority of the gas. A lesser fee does apply to a small number of specific wells in the area.

 

Competition

 

We operate in a highly competitive environment for acquiring properties and other energy companies, attracting capital, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for mineral property acquisitions. Competition is intense for the acquisition of leases considered favorable for the development of hydrocarbons in commercial quantities. Our competitors may be able to pay more for hydrocarbon properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of hydrocarbons but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling natural gas, crude oil, and natural gas liquids.  Many of our competitors possess greater financial and other resources which may enable them to identify and acquire desirable properties and market their hydrocarbon production more effectively than we do.

 

Markets

 

The availability of a ready market for natural gas, oil and natural gas liquids and the price obtained, depends upon numerous factors beyond our control. Product availability and price are the principal means of competition in selling natural gas, oil and NGLs. During the years ended December 31, 2015 and 2014, we did not experience problems in selling our natural gas, oil and NGLs, although prices have varied significantly during those periods.

 

Seasonal Nature of Business

 

Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. In addition, seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in certain areas. These seasonal anomalies may pose challenges for meeting our well construction objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay our operations.

 


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Environmental Matters and Regulation

 

Our operations relating to drilling and waste disposal are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As operators within the complex natural gas and oil industry, we must comply with laws and regulations at the federal, state and local levels. These laws and regulations can restrict or affect our business activities in many ways, such as by:

 

 

·

restricting the way waste disposal is handled;

 

·

limiting or prohibiting drilling, construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by threatened or endangered species;

 

·

requiring the acquisition of various permits before the commencement of drilling;

 

·

requiring the installation of expensive pollution control equipment and water treatment facilities;

 

·

restricting the types, quantities and concentration of various substances that can be released into the environment in connection with siting, drilling, completion, production, and plugging activities;

 

·

requiring remedial measures to reduce, mitigate and/or respond to releases of pollutants or hazardous substances from existing and former operations, such as pit closure and plugging of abandoned wells;

 

·

enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations;

 

·

imposing substantial liabilities for pollution resulting from operations; and

 

·

requiring preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases.

 

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs.

 

We believe that our operations are in substantial compliance with applicable environmental laws and regulations, and compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot assure future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

 

Environmental laws and regulations that could have a material impact on our operations include the following:

 

National Environmental Policy Act. Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or “NEPA”. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will typically require an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that will be made available for public review and comment. All of our proposed exploration and production activities on federal lands, if any, require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

 


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Waste Handling. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act, or “RCRA”, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“USEPA”), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development and production of crude oil and natural gas constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that USEPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as solid waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

 

We believe that our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that they are required under such laws and regulations. Although we do not believe the current costs of managing wastes to be significant, any more stringent regulation of natural gas and oil exploitation and production wastes could increase the costs to manage and dispose of such wastes.

 

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe that we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us. However, none of these spills or releases appears to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them, may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination.

 

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, the federal regulations that implement the Clean Water Act, and analogous state laws and regulations impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by USEPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. Further, much of our natural gas extraction activity utilizes a process called hydraulic fracturing, which results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

 


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On April 21, 2014, the U.S. Army Corps of Engineers (“USACE”) and USEPA proposed a rule that would define ‘Waters of the United States’ (“WOTUS”), i.e., the scope of waters protected under the Clean Water Act, in light of several U.S. Supreme Court opinions (U.S. v. Riverside Bayview, Rapanos v. United States, and Solid Waste Agency of Northern Cook County v. U.S. Army Corps of Engineers). The public comment period concluded on November 14, 2014 and USEPA received hundreds of thousands of comments on the proposed rule. On May 27, 2015, USEPA and USACE announced the final rule redefining the extent of the agencies’ jurisdiction over WOTUS, and the final rule was published in the Federal Register on June 29, 2015 with an effective date of August 28, 2015. The final rule was immediately challenged by multiple parties, including individual states, in both United States District Courts and U.S. Circuit Courts of Appeals. On October 9, 2015, the 6th Circuit Court of Appeals found that the petitioners, totaling 18 states, demonstrated a “substantial possibility of success on the merits of the claim” and issued a nationwide stay of the WOTUS final rule. Currently, this nationwide stay is in place and the litigation in both the U.S. District and Circuit Courts is ongoing. Additionally, there have been legislative efforts by the General Assembly to nullify the rule, specifically a joint resolution of Congress passed under authority of the Congressional Review Act that was vetoed by President Obama on January 19, 2016. As drafted, the final rule is broader in scope then the current rule, and will increase the costs of compliance and result in additional permitting requirements for some of our existing or future facilities.

 

The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that our operations are in substantial compliance with the requirements of the Clean Water Act.

 

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, the federal regulations that implement the Clean Air Act, and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including drilling sites, processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Such laws and regulations may require obtaining pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions. Air permits contain various emissions and operational limitations, and may require specific emission control technologies to limit emissions. Various air quality regulations are periodically reviewed by USEPA and are amended as deemed necessary. USEPA may also issue new regulations based on changing environmental concerns.

 

Recent revisions to federal Clean Air Act rules impose additional emissions control requirements and practices on our operations. New facilities, if any, may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new or revised requirements. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe that our operations are in substantial compliance with the requirements of the Clean Air Act and comparable state laws and regulations.

 

While we will likely be required to incur certain capital expenditures in the future for air pollution control equipment to comply with applicable regulations and to obtain and maintain operating permits and approvals for air emissions, we believe that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.

 

OSHA and Other Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act, or “OSHA”, and comparable state statutes. The OSHA hazard communication standard, USEPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

 

On October 22, 2015, USEPA responded to an October 24, 2012 petition to USEPA requesting that the oil and gas extraction industrial sector be added to the sectors with reporting requirements covered by Section 313 of the Emergency Planning and Community Right-to-Know Act (the Toxics Release Inventory or “TRI”). In its response, USEPA stated that it intends to propose a rulemaking that would subject natural gas processing facilities that employ more than 10 people to annual TRI reporting, but that USEPA will not propose that well sites, compressor stations, pipelines, and other oil and gas extraction industrial sector facilities be subject to TRI reporting.  

 


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Additionally, the White House Office of Management and Budget received OSHA’s final “Occupational Exposure to Crystalline Silica” rule on December 21, 2015. The final rule has not been published, but is expected to follow OSHA’s proposed rule from September 12, 2013 that would impose a new exposure limit for silica and with it various new requirements. The federal 2015 Fall Unified Agenda and Regulatory Plan lists February 2016 as the target release date for the final rulemaking. OSHA has previously addressed respirable silica from the oil and gas industry operations back in December 2014 when it released a “Hydraulic Fracturing and Flowback Hazards Other than Respirable Silica” safety alert. If finalized, the rule would likely result in significant costs for the oil and gas industry to comply with the new requirements.  

 

Greenhouse Gas Regulation and Climate Change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, Congress has been actively considering climate change legislation. More directly, USEPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are air pollutants covered by the Clean Air Act), USEPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (Dec. 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, USEPA has promulgated two final rules relating to greenhouse gases that will affect our businesses.

 

First, USEPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31,514 (June 3, 2010). Both the federal preconstruction review program, known as “Prevention of Significant Deterioration” (“PSD”), and the operating permit program are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain the requisite operating permits.

 

On June 23, 2014, the United States Supreme Court ruled on challenges to the Tailoring Rule in the case of Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2014). The Court limited the applicability of the PSD program and Tailoring Rule to only new sources or modifications that would trigger PSD for another criteria pollutant such that projects cannot trigger PSD based solely on greenhouse gas emissions. However, if PSD is triggered for another pollutant, greenhouse gases could be subject to a control technology review process. The Court’s decision also means that sources cannot trigger a federal operating permit requirement based solely on greenhouse gas emissions. Overall, the impact of the Tailoring Rule after the Court’s decision is that it is unlikely to have much, if any, impact on our operations. However, USEPA is still in the process of responding to the Court’s decision through rulemakings.

 

Second, USEPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (Oct. 2009). Subsequent revisions, additions and clarifications were promulgated, including a rule subpart specifically addressing the natural gas industry. This particular subpart was most recently revised in October 2015, 80 Fed. Reg. 64262 (Oct. 22, 2015), when USEPA finalized changes to calculation methods, monitoring and data reporting requirements, and other provisions. Shortly thereafter, in January 2016, USEPA proposed additional revisions to the broader Greenhouse Gas Reporting for public comment. In general, the Greenhouse Gas Reporting Rule requires certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to USEPA on an annual basis. The natural gas industry is covered by the rule and requires annual greenhouse gas emissions to be reported by March 31 of each year for the emissions during the preceding calendar year. This rule imposes additional obligations on us to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions.

 

In addition to these existing rules, the Obama Administration announced in January 2015 that it was developing additional rules to curb greenhouse gas emissions from the oil and gas sector, as part of a new national strategy for reducing methane emissions from the sector by 40 – 45% from 2012 levels by the year 2025. This national methane reduction strategy targeting the oil and gas sector is related to the Obama Administration’s broader Climate Action Plan of 2013. Multiple federal agencies, including USEPA and the U.S. Department of the Interior’s Bureau of Land Management, which we refer to as the BLM, are involved in implementing the national methane reduction strategy.

 


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In August 2015, USEPA proposed a broad suite of regulatory measures to implement the national methane reduction strategy, as well as to reduce emissions of ozone-forming volatile organic compounds (“VOCs”) and clarify air permitting requirements for the oil and gas sector. The proposed measures include: (1) a revised New Source Performance Standards (“NSPS”) rule for oil and natural gas production, transmission, and distribution that would expand existing requirements for sources of VOCs and establish new requirements for sources of methane; (2) draft Control Techniques Guidelines that direct states to adopt regulations for reducing VOC emissions from existing oil and gas facilities in certain ozone nonattainment areas and states in the Ozone Transport Region; (3) a Federal Implementation Plan for certain oil and gas operations located in Indian country; and (4) a rule defining the circumstances in which oil and gas equipment and activities are to be considered part of a source that is subject to “major source” permitting requirements under the Clean Air Act.  USEPA accepted public comments on these proposals through early December 2015. The proposals are expected to be finalized in 2016.

 

Consistent with the Obama Administration’s methane reduction strategy, on January 22, 2016, BLM released a proposed rule to update standards for venting, flaring, and equipment leaks from oil and gas production activities on onshore Federal and Indian leases. BLM’s existing requirements are more than three decades old. According to BLM, the proposed rule would ensure that operators use modern best practices to minimize waste of produced natural gas and reduce emissions of methane and VOCs.

 

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus, future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

 

In addition to domestic regulatory developments, the United States is a participant in multi-national discussions intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements (e.g., the “Paris Agreement”, reached at the United Nations Conference on Climate Change in December 2015) that could have an impact on our business.

 

Finally, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe that these conditions are having any material current adverse impact on our business, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

 

Energy Policy Act. Much of our natural gas extraction activity utilizes a process called hydraulic fracturing. The Energy Policy Act of 2005 amended the definition of “underground injection” in the Federal Safe Drinking Water Act of 1974, or “SDWA”. This amendment effectively excluded hydraulic fracturing for oil, gas or geothermal activities from the SDWA permitting requirements, except when “diesel fuels” are used in the hydraulic fracturing operations. Recently, this subject has received much regulatory and legislative attention at both the federal and state level and we anticipate that the permitting and compliance requirements applicable to hydraulic fracturing activity are likely to become more stringent and could have a material adverse impact on our business and operations. For instance, USEPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels in February 2014, along with responses to selected substantive public comments on USEPA’s previous draft guidance, a fact sheet and a memorandum to USEPA’s regional offices regarding implementation of the guidance. The process for implementing USEPA’s final guidance document may vary across states depending on the regulatory authority responsible for implementing the SDWA UIC program in each state.

 

The U.S. Senate and House of Representatives considered legislative bills in the 111th, 112th, and 113th Sessions of Congress that, if enacted, would have repealed the SDWA permitting exemption for hydraulic fracturing activities. Titled the “Fracturing Responsibility and Awareness of Chemicals Act,” or “Frac Act”, the legislative bills as proposed could have potentially led to significant oversight of hydraulic fracturing activities by federal and state agencies. The Frac Act was re-introduced in the current 114th Session of Congress and referred to the Committee on Environment and Public Works; if enacted into law, the legislation as proposed could potentially result in significant regulatory oversight, which may include additional permitting, monitoring, recording and recordkeeping requirements for us.

 


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We believe our operations are in substantial compliance with existing SDWA requirements. However, future compliance with the SDWA could result in additional requirements and costs due to the possibility that new or amended laws, regulations or policies could be implemented or enacted in the future.

 

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. We conduct our natural gas extraction activities in certain formations where hydrogen sulfide may be, or is known to be, present. The MGP employs numerous safety precautions at our operations to ensure the safety of its employees. There are various federal and state environmental and safety requirements for handling sour gas, and we are in substantial compliance with all such requirements.

 

Drilling and Production. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax or impact fee with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

 

State Regulation and Taxation of Drilling. The various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Pennsylvania has imposed an impact fee on wells drilled into an unconventional formation, which includes the Marcellus Shale. The impact fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. For example, based upon natural gas prices for 2015, the impact fee for qualifying unconventional horizontal wells spudded during 2015 was $45,300 per well, while the impact fee for unconventional vertical wells was $9,100 per well. The payment structure for the impact fee makes the fee due the year after an unconventional well is spudded, and the fee will continue for 15 years for an unconventional horizontal well and 10 years for an unconventional vertical well. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources.

 

States may regulate rates of production and may establish maximum limits on daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells, the type of wells that may be drilled in the future in proximity to existing wells and to limit the number of wells or locations from which we can drill.

 

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on our business.

 

Oil Spills and Hydraulic Fracturing. The Oil Pollution Act of 1990, as amended (“OPA”), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

 


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A number of federal agencies, including USEPA and the Department of Interior, are currently evaluating a variety of environmental issues related to hydraulic fracturing. For example, USEPA is conducting a study that evaluates any potential effects of hydraulic fracturing on drinking water and ground water. On December 9, 2013, USEPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Individual research projects associated with USEPA’s study were published in July 2014. On June 4, 2015, the EPA released its draft “Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources” (the “Draft Assessment”), in addition to nine new peer-reviewed scientific reports that formed the basis for certain findings included in the Draft Assessment. The scope of  the Draft Assessment focuses on potential impacts to drinking water resources by hydraulic fracturing, specifically the following water activities that the EPA has identified as the “hydraulic fracturing water cycle” in the Draft Assessment: water acquisition from ground or surface waters; chemical mixing at the well site; well injection of hydraulic fracturing fluids; the collection and handling of wastewater from hydraulic fracturing (such as flowback and produced water); and wastewater treatment and waste disposal.  The EPA revealed in its Draft Assessment that it has not found any evidence that hydraulic fracturing activities are performed in a way that leads to widespread, systemic impacts on drinking water resources. The EPA did identify specific instances where hydraulic fracturing activities may have led to impacts to drinking water; however, the EPA noted that those instances are minimal when compared to the number of hydraulically fractured wells in the United States. Notice of the Draft Assessment was published in the June 5, 2015 Federal Register, and several public teleconference calls and a public meeting were held by the USEPA’s Science Advisory Board (SAB) to discuss the Draft Assessment. On January 7, 2016, the SAB released a Draft Review of the USEPA’s Draft Assessment. The Draft Review includes many recommendations to USEPA that SAB believes USEPA should consider to improve the Draft Assessment. These recommendations include, but are not limited to: revising its draft finding that USEPA found no “evidence that hydraulic fracturing mechanisms have led to widespread, systemic impacts on drinking water resources,” as the SAB found the statement to be ambiguous and therefore require clarification and additional explanation; adding further discussion on the Pavillion, Wyoming; Parker County, Texas; and Dimock, Pennsylvania investigations; collecting and add new data regarding the chemicals used during hydraulic fracturing and the content of flowback water; and adding Best Management Practices and suggested improvements to each stage of the hydraulic fracturing process.

 

BLM proposed a rule on May 11, 2012 that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, BLM published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. On March 26, 2015, BLM issued a final rule updating the regulations governing hydraulic fracturing on federal and Indian lands. Among the many new requirements, the final rule requires operators planning to conduct hydraulic fracturing to design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate usable water, as well as requires operators to monitor cementing operations during well completion. Additionally, the final rule requires that companies publicly disclose the chemicals used in the hydraulic fracturing process, subject to limited exceptions for trade secret materials; comply with safety standards for storage of produced water in rigid enclosed, covered, or netted and screened above-ground tanks, with very limited exceptions allowing use of pits that must be approved by BLM on a case-by-case basis; and submit detailed information to the BLM on proposed operations, including but not limited to well geology, location of faults and fractures, estimated volume of fluid to be used, and estimated direction and length of fractures.  The final rule also provides that for certain circumstances in which specific state or tribal regulations are equally or more protective than the BLM’s new rules, the state or tribe may obtain a variance for that specific regulation. The final rule was set to go into effect on June 24, 2015. However on June 23, 2015, the U.S. District Court for the District of Wyoming announced a stay on the effective date of the rule in State of Wyoming v. Dep't of Interior, No. 2:15-cv-00043, a lawsuit that involves several states and industry associations who requested that the Court grant a preliminary injunction of the final rule. On September 30, 2015, the U.S. District Court granted the preliminary injunction, thus enjoining the final rule.

 


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In addition, state and local conservancy districts and river basin commissions have all previously exercised their various regulatory powers to curtail and, in some cases, place moratoriums on hydraulic fracturing. State regulations include express inclusion of hydraulic fracturing into existing regulations covering other aspects of exploration and production and specifically may include the following:

 

 

·

requirement that logs and pressure test results are included in disclosures to state authorities;

 

·

disclosure of hydraulic fracturing fluids and chemicals, potentially subject to trade secret/confidential proprietary information protections, and the ratios of same used in operations;

 

·

specific disposal regimens for hydraulic fracturing fluids;

 

·

replacement/remediation of contaminated water assets; and

 

·

minimum depth of hydraulic fracturing.

 

Local regulations, which may be preempted by state and federal regulations, have included, but have not been limited to, the following, which may extend to all operations including those beyond hydraulic fracturing:

 

 

·

noise control ordinances;

 

·

traffic control ordinances;

 

·

limitations on the hours of operations; and

 

·

mandatory reporting of accidents, spills and pressure test failures.

 

Other Regulation of the Natural Gas and Oil Industry. The natural gas and oil industry is extensively regulated by federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on the industry. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

 

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Employees

We do not directly employ any of the persons responsible for our management or operation. In general, personnel employed by Atlas Energy Group manage and operate our business. Some of the officers of our general partner may spend a substantial amount of time managing the business and affairs of our general partner and its affiliates other than us and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and any amendments to those reports, available through our MGP’s website at www.atlasresourcepartners.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”). To view these reports, click on “Investment Programs”, then “Drilling Program SEC Filings” and finally the respective program of your inquiry. You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive, Suite 400, Pittsburgh, Pennsylvania 15275, telephone number (800) 251-0171. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the Securities and Exchange Commission’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.


19


 

 

 

ITEM 2: PROPERTIES

Natural Gas, Oil and NGL Reserves

The following tables summarize information regarding our estimated proved natural gas, oil and NGL reserves as of December 31, 2015 and 2014. Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. All of the reserves are located in the United States. We base these estimated proved natural gas, oil and NGL reserves and future net revenues of natural gas, oil and NGL reserves upon reports prepared by Wright & Company, Inc., an independent third-party reserve engineer. We have adjusted these estimates to reflect the settlement of asset retirement obligations on gas, oil and NGL properties. A summary of the reserve report related to our estimated proved reserves at December 31, 2015 is included as Exhibit 99.1 to this report. In accordance with SEC guidelines, we make the standardized measure estimates of future net cash flows from proved reserves using natural gas, oil and NGL sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. Our estimates of proved reserves are calculated on the basis of the unweighted adjusted average of the first-day-of-the-month price for each month during the years ended December 31, 2015 and 2014 and are adjusted for basis differentials:

 

 

December 31,

 

 

2015

 

  

2014

 

Natural gas (per Mcf)

$

2.59

  

  

$

4.35

  

Oil (per Bbl)

$

50.28

  

  

$

94.99

  

Natural gas liquids (per Bbl)

$

11.02

  

  

$

30.21

  

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas, oil and NGL reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGL that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

The preparation of our natural gas, oil and NGL reserve estimates was completed in accordance with our MGP’s prescribed internal control procedures by its reserve engineers. For the periods presented, Wright & Company, Inc., was retained to prepare a report of proved reserves. The reserve information includes natural gas and oil reserves which are all located in the United States. The independent reserves engineer’s evaluation was based on more than 39 years of experience in the estimation of and evaluation of petroleum reserves, specified economic parameters, operating conditions, and government regulations. Our MGP’s internal control procedures include verification of input data delivered to our third-party reserve specialist, as well as a multi-functional management review. The preparation of reserve estimates was overseen by our MGP’s Senior Reserve Engineer, who is a member of the Society of Petroleum Engineers and has more than 17 years of natural gas and oil industry experience. The reserve estimates were reviewed and approved by our MGP’s Senior Engineering Staff and management, with final approval by our MGP’s President.

Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of these estimates. Future prices received from the sale of natural gas, oil and NGL may be different from those estimated by Wright & Company, Inc., in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced. You should not construe the estimated standardized measure values as representative of the current or future fair market value of our proved natural gas, oil and NGL properties. Standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas, oil and NGL prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. We deduct operating costs, development costs and production-related and ad valorem taxes in arriving at the estimated future cash flows. Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. We base the estimates on operating methods and conditions prevailing as of the dates indicated.


20


 

 

 

 

Proved Reserves at December 31,

 

 

2015 (4)

 

  

2014

 

Proved developed reserves (3):

 

 

 

  

 

 

 

Natural gas reserves (Mcf)

 

11,083,900

  

  

 

18,078,700

  

Oil reserves (Bbl)

 

15,200

  

  

 

18,000

  

Natural gas liquids (Bbl)

 

38,300

  

  

 

49,300

  

Total proved developed reserves (Mcfe)

 

11,404,900

  

  

 

18,482,500

  

Standardized measure of discounted future cash flows (1)

$

3,385,800

  

  

$

17,686,000

  

Standardized measure of discounted future cash flows per Limited Partner Unit (2)

$

198

  

  

$

1,036

  

Undiscounted future cash flows per Limited Partner Unit

$

375

  

  

$

2,130

  

 

 

 

(1)

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we are a limited partnership, no provision for federal or state income taxes has been included in the December 31, 2015 and 2014 calculations of standardized measure, which is, therefore, the same as the PV-10 value.

 

(2)

This value per limited partner unit is determined by following the methodology used for determining our proved reserves using the data discussed above. However, this value does not necessarily reflect the fair market value of a unit, and each unit is illiquid. Also, the value of the unit for purposes of presentment of the unit to our MGP for purchase is different, because it is calculated under a formula set forth in the Partnership Agreement.

 

(3)

The Partnership does not have any proved undeveloped reserves as of December 31, 2015 and 2014.

 

(4)

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgement on the potential value of recoverable reserves or in estimating future results of operations.


21


 

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests in gross wells. The following table sets forth information regarding productive natural gas wells in which we have a working interest as of December 31, 2015:

 

 

Number of productive wells

 

 

Gross

 

  

Net

 

Gas wells

 

71.00

 

 

 

45.31

  

Developed Acreage

The following table sets forth information about our developed natural gas acreage as of December 31, 2015:

 

 

Developed Acreage

 

 

Gross

 

  

Net

 

Pennsylvania

 

1,268.94

 

 

 

751.09

 

Tennessee

 

510.37

 

 

 

318.93

 

Indiana

 

140.33

 

 

 

125.83

 

Total

 

1,919.64

 

 

 

1,195.86

 

The leases for our developed acreage generally have terms that extend for the life of the wells. We believe that we hold good and indefeasible title to our producing properties, in accordance with standards generally accepted in the natural gas industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we commence drilling operations, we conduct an extensive title examination and we perform curative work on defects that we deem significant. We or our predecessors have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry. Our properties are also subject to burdens such as liens incident to operating agreements, taxes, development obligations under natural gas and oil leases, farm-out arrangements and other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties.

 

ITEM  3: LEGAL PROCEEDINGS

We are party to various routine legal proceedings arising out of the ordinary course of our business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. (See Item 8: Note 9 Commitments and Contingencies).

 

Affiliates of the MGP and their subsidiaries are party to various routine legal proceedings arising in the ordinary course of their respective businesses. The MGP’s management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the MGP’s financial condition or results of operations.

 

ITEM  4: MINE SAFETY DISCLOSURES (Not applicable)


22


 

 

PART II

 

ITEM  5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

There is no established public trading market for our units and we do not anticipate that a market for our units will develop. Our units may be transferred only in accordance with the provisions of Article VI of our Partnership Agreement which requires:

 

 

our MGP’s consent;

 

the transfer not result in materially adverse tax consequences to us; and

 

the transfer does not violate federal or state securities laws.

 

An assignee of a unit may become a substituted partner only upon meeting the following conditions:

 

 

the assignor gives the assignee the right;

 

our MGP consents to the substitution;

 

the assignee pays to us all costs and expenses incurred in connection with the substitution; and

 

the assignee executes and delivers the instruments, which our MGP requires to effect the substitution and to confirm his or her agreement to be bound by the term of our partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. As of December 31, 2015, we had 3,275 limited partners.

Our MGP reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. We distribute those funds which our MGP determines are not necessary for us to retain. We will not advance or borrow funds for purposes of making distributions. During the years ended December 31, 2015 and 2014, we distributed the following:

 

 

Distributions

 

 

2015

 

  

2014

 

Limited Partners

$

883,500

  

  

$

3,988,800

  

Managing General Partner

 

233,700

  

  

 

715,600

  

Total distributions

$

1,117,200

  

  

$

4,704,400

  

 

ITEM 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The discussion and analysis presented below provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with Item 8: Financial Statements and Supplementary Data, which contains our financial statements.

The following discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Forward-looking statements speak only as of the date the statements were made. The matters discussed in these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from those made, projected or implied in the forward-looking statements. We believe the assumptions underlying the financial statements are reasonable. However, our financial statements included herein may not necessarily reflect our results of operations, financial position and cash flows in the future.


23


 

BUSINESS OVERVIEW

Atlas Resources Public #18-2009 (B) L.P. (“we”, “us” or the “Partnership”) is a Delaware limited partnership and formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

 

On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS).  Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.

The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee and Indiana. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations has been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical to produce our wells until they are depleted, as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our ability to continue as a going concern.

The following discussion provides information to assist in understanding our financial condition and results of operations. Our operating cash flows are generated from our wells, which primarily produce natural gas, but also some oil. Our produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. Our ongoing operating and maintenance costs have been and are expected to be fulfilled through revenues from the sale of our natural gas and oil production. We pay our MGP, as operator, a monthly well supervision fee, which covers all normal and regularly recurring operating expenses for the production and sale of natural gas and oil such as:

 

 

Well tending, routine maintenance and adjustment;

 

Reading meters, recording production, pumping, maintaining appropriate books and records; and

 

Preparation of reports for us and government agencies.


24


 

The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials, and brine disposal. If these expenses are incurred, we pay cost for third-party services, materials, and a competitive charge for service performed directly by our MGP or its affiliates. Also, beginning one year after each of our wells has been placed into production, our MGP, as operator, may retain $200 per month, per well, to cover the estimated future plugging and abandonment costs of the well. As of December 31, 2015, our MGP withheld $69,400 of net production revenue for this purpose.

MARKETS AND COMPETITION

The availability of a ready market for natural gas and oil produced by us, and the price obtained, depends on numerous factors beyond our control, including the extent of domestic production, imports of foreign natural gas and oil, political instability or terrorist acts in gas and oil producing countries and regions, market demand, competition from other energy sources, the effect of federal regulation on the sale of natural gas and oil in interstate commerce, other governmental regulation of the production and transportation of natural gas and oil and the proximity, availability and capacity of pipelines and other required facilities. Our MGP is responsible for selling our production. During 2015 and 2014, we experienced no problems in selling our natural gas and oil. Product availability and price are the principal means of competing in selling natural gas and oil production. While it is impossible to accurately determine our comparative position in the industry, we do not consider our operations to be a significant factor in the industry.

Natural Gas. The MGP markets the majority of our natural gas production to gas marketers directly or to third party plant operators who process and market the gas. The sales price of natural gas produced is a function of the market in the area and typically tied to a regional index. The production area and pricing indices for the Appalachian Basin are Dominion South Point, Tennessee Gas Pipeline, Transco Leidy Line, Columbia Appalachia, NYMEX and Transco Zone 5.

We do not hold firm transportation obligations on any pipeline that requires payment of transportation fees regardless of natural gas production volumes. As is customary in certain of our other operating areas, we occasionally commit a predictable portion of monthly production to the purchaser in order to maintain a gathering agreement.

Crude Oil. Crude oil produced from our wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. The crude oil is typically sold at the prevailing spot market price for each region, less appropriate trucking charges. We do not have delivery commitments for fixed and determinable quantities of crude oil in any future periods under existing contracts or agreements.

Natural Gas Liquids. NGLs are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport to end users or marketers operating on the receiving pipeline. The resulting dry natural gas is sold as described above and our NGLs are generally priced using the Mont Belvieu (TX) or Conway (KS) regional processing indices. The cost to process and fractionate the NGLs from the gas stream is typically either a volumetric fee for the gas and liquids processed or a volumetric retention by the processing and fractionation facility. We do not have delivery commitments for fixed and determinable quantities of NGLs in any future periods under existing contracts or agreements.

For the year ended December 31, 2015, Chevron Natural Gas and Atmos Energy Marketing, LLC accounted for approximately 81% and 13%, respectively, of our total natural gas, oil and NGL production revenues, with no other single customer accounting for more than 10% of revenues for this period.

GENERAL TRENDS AND OUTLOOK

 

We expect our business to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015 The causes of these declines are based on a number of factors, including, but not limited to, a significant increase in natural gas, oil and NGL production. While we anticipate continued high levels of exploration and production activities over the long-term in the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments in the development of new natural gas, oil and NGL reserves.

 

Our future gas and oil reserves, production, cash flow, our ability to make distributions to our unitholders, depend on our success in producing our current reserves efficiently. We face the challenge of natural production declines and volatile natural gas, oil and NGL prices. As initial reservoir pressures are depleted, natural gas and oil production from particular wells decreases.


25


 

RESULTS OF OPERATIONS

GAS AND OIL PRODUCTION: The following table sets forth information related to our production revenues, volumes, sales prices, production costs and depletion during the periods indicated:

 

 

Years Ended December 31,

 

 

2015

 

 

2014

 

Production revenues (in thousands):

 

 

 

 

 

 

 

Gas

$

2,382

  

 

$

5,542

  

Oil

 

1

  

 

 

5

  

Total

$

2,383

  

 

$

5,547

  

 

Production volumes:

 

 

 

 

 

 

 

Gas (mcf/day)

 

3,725

  

 

 

4,529

  

Oil (bbls/day)

 

-

  

 

 

1

  

Total (mcfe/day)

 

3,725

  

 

 

4,535

  

 

Average sales price: (1)

 

 

 

 

 

 

 

Gas (per mcf) (2)

$

1.80

  

 

$

3.46

  

Oil (per bbl)

$

43.86

  

 

$

89.88

  

 

Production costs:

 

 

 

 

 

 

 

As a percent of revenues

 

71

 

 

41

Per mcfe

$

1.24

  

 

$

1.37

  

Depletion per mcfe

$

0.97

  

 

$

1.18

  

 

 

(1)

Average sales prices represent accrual basis pricing after reversing the effect of previously recognized gains resulting from prior period impairment charges.

 

(2)

Average gas prices are calculated by including in total revenue derivative gains previously recognized into income in connection with prior period impairment charges and dividing by the total volume for the period. Previously recognized derivative gains were $69,200 and $183,300 for the years ended December 31, 2015 and 2014, respectively.

Natural Gas Revenues. Our natural gas revenues were $2,381,900 and $5,541,700 for the years ended December 31, 2015 and 2014, respectively, a decrease of $3,159,800 (57%). The $3,159,800 decrease in natural gas revenues for the year ended December 31, 2015 as compared to the prior year was attributable to $2,175,900 decrease in natural gas prices after the effect of financial hedges, which were driven by market conditions, and a $983,900 decrease in production volumes. Our production volumes decreased to 3,725 mcf per day for the year ended December 31, 2015 from 4,529 mcf per day for the year ended December 31, 2014, a decrease of 804 (18%) mcf per day. The price we receive for our natural gas is primarily a result of the index driven agreements (See Item 1: “Business-Contractual Revenue Arrangements”). Thus, the price we receive for our natural gas may vary significantly each month as the underlying index changes in response to market conditions. The decrease in production volume is mostly due to the normal decline inherent in the life of the wells in addition to wells shut-in due to it being uneconomical to continue production in the current pricing environment.

Oil Revenues. We drilled wells primarily to produce natural gas, rather than oil, but some wells have limited oil production. Our oil revenues were $1,100 and $4,900 for the years ended December 31, 2015 and 2014, respectively, a decrease of $3,800 (78%). The $3,800 decrease in oil revenues for the year ended December 31, 2015 as compared to the prior year was attributable to a $2,700 decrease in production volumes and a $1,100 decrease in oil prices. Our production volumes decreased to 0.07 bbl per day for the year ended December 31, 2015 from 0.15 bbls per day for the year ended December 31, 2014, a decrease of 0.08 bbl per day (53%).


26


 

Gain on Mark-to-Market Derivatives. On January 1, 2015, we discontinued hedge accounting for our qualified commodity derivatives. As such, subsequent changes in fair value of these derivatives are recognized immediately within gain on mark-to-market derivatives on our statements of operations. The fair values of these commodity derivative instruments as of December 31, 2014, which were recognized in accumulated other comprehensive income within partners’ capital on our balance sheet, will be reclassified to our statements of operations in the future at the time the originally hedged physical transactions settle.

We recognized a gain on mark-to-market derivatives of $304,900 for the year ended December 31, 2015. This gain was due primarily to mark-to-market gains in the current year primarily related to the change in natural gas prices during the year. There were no gains or losses on mark-to-market derivatives during the year ended December 31, 2014.

Costs and Expenses. Production expenses were $1,689,600 and $2,268,700 for the years ended December 31, 2015 and 2014, respectively, a decrease of $579,100 (26%). This decrease was the result of lower transportation expenses due to lower natural gas sales prices and production volumes as wells were shut-in due to being uneconomical in the current pricing environment.

Depletion of our gas and oil properties as a percentage of gas and oil revenues was 55% and 35% for the years ended December 31, 2015 and 2014, respectively. This change was primarily attributable to changes in gas and oil reserve quantities and to a lesser extent revenues, product prices and production volumes and changes in the depletable cost basis of gas and oil properties.

General and administrative expenses were $106,200 and $104,100 for the years ended December 31, 2015 and 2014, respectively, an increase of $2,100 (2%). These expenses include third-party costs for services as well as the monthly administrative fees charged by our MGP and vary from period to period due to the costs and services provided to us.

Impairments of gas and oil properties for the years ended December 31, 2015 and 2014 were $15,228,700 and $297,500, respectively, net of offsetting gains from accumulated other comprehensive income of $222,800 and $0, respectively. At least annually, we compare the carrying value of our proved developed gas and oil producing properties to their estimated fair market value. To the extent our carrying value exceeds the estimated fair market value, an impairment charge is recognized. As a result of this assessment, an impairment charge was recognized for the years ended December 31, 2015 and 2014. This charge is based on reserve quantities, future market prices and our carrying value. We cannot provide any assurance that similar charges may or may not be taken in future periods.

Liquidity and Capital Resources. We are generally limited to the amount of funds generated by the cash flow from our operations to fund our obligations and make distributions to our partners.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015.  The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact our outlook. We have experienced downward revisions of our natural gas and oil reserves volumes and values due to the significant declines in commodity prices. Our MGP continues to implement various cost saving measures to reduce our operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. Our MGP will continue to be opportunistic and aggressive in managing our cost structure and, in turn, our liquidity to meet our operating needs. To the extent commodity prices remain low or decline further, or we experience other disruptions in the industry, our ability to fund our operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate our operations.

Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from our operations has been adequate to fund our obligations and distributions to our partners. However, the recent significant declines in commodity prices have challenged our ability to fund our operations and may make it uneconomical to produce our wells until they are depleted, as we originally intended. Accordingly, the MGP determined that there is substantial doubt about our ability to continue as a going concern. The MGP intends, as necessary, to continue our operations and to fund our obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to our ability to continue as a going concern.

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from of distributions to the limited partners.


27


 

 

Cash provided by operating activities decreased $2,789,000 for the year ended December 31, 2015 to $1,187,700 as compared to $3,976,700 for the year ended December 31, 2014. This decrease was primarily due to a decrease in net earnings before depletion, impairment and accretion of $2,281,700, a decrease in the non-cash (gain) loss on derivative value of $289,400, a decrease in the change in accounts receivable trade-affiliate of $228,200, and a decrease in asset retirement receivable-affiliate of $22,000. The decrease was partially offset by an increase in the change in accrued liabilities of $16,300 and the change in accounts payable trade-affiliate of $16,000 for the year ended December 31, 2015, compared to the year ended December 31, 2014.

Cash provided by investing activities was $3,400 for the year ended December 31, 2015 resulting from proceeds from the sale of miscellaneous tangible equipment. Cash used in investing activities was $373,900 for the year ended December 31, 2014 resulting from the net of $9,400 in proceeds from the sale of tangible equipment and the proceeds from the sale of the Partnership’s Michigan oil and gas properties of $369,000, partially offset by a purchase of tangible equipment of $4,500.

Cash used in financing activities decreased $3,587,200 to $1,117,200 for the year ended December 31, 2015 from $4,704,400 for the year ended December 31, 2014. This decrease was due to a decrease in cash distributions to partners.

Our MGP may withhold funds for future plugging and abandonment costs. Through December 31, 2015, our MGP withheld $69,400 of funds for this purpose. Any additional funds, if required, will be obtained from production revenues or borrowings from our MGP or its affiliates, which are not contractually committed to make loans to us. The amount that we may borrow at any one time may not at any time exceed 5% of our total subscriptions, and we will not borrow from third-parties.

 

Impairment

During the years ended December 31, 2015 and 2014, we recognized $15,228,700 and $297,500, respectively, of impairments related to gas and oil properties within gas and oil properties on our balance sheets, net of offsetting gains from accumulated other comprehensive income of $222,800 and $0, respectively. These impairments related to the carrying amount of our gas and oil properties being in excess of our estimate of their fair value at December 31, 2015 and 2014. The estimates of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices.

 

ENVIRONMENTAL REGULATION

 

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety (see “Item 1: Business —Environmental Matters and Regulation”). We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; imposition of remedial requirements; issuance of injunctions affecting our operations; or other measures. We have maintained and expect to continue to maintain environmental compliance programs. However, risks of accidental leaks or spills are associated with our operations. There can be no assurance that we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible other developments, such as increasingly strict federal, state and local environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

 

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate that such changes will continue. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on operations, such as emissions of greenhouse gases and other pollutants; generation and disposal of wastes, including wastes that may have technologically enhanced naturally occurring radioactive materials; and use, storage and handling of chemical substances that may impact human health, the environment and/or threatened or endangered species. Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible that the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance that we will identify and properly anticipate each such change, or that our efforts will prevent material costs, if any, from rising.


28


 

 

 

CHANGES IN PRICES AND INFLATION

Our revenues and the value of our assets have been and will continue to be affected by changes in natural gas and oil market prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. Inflation affects the operating expenses of our operations. Inflationary trends may occur if commodity prices were to increase, since such an increase may cause the demand for energy equipment and services to increase, thereby increasing the costs of acquiring or obtaining such equipment and services. While we anticipate that inflation will affect our future operating costs, we cannot predict the timing or amounts of any such effects.

 

SECURED HEDGE FACILITY

The MGP has a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas and oil properties and first priority security interests in substantially all of its assets and by a guarantee of the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. As of December 31, 2015, only the Partnership’s natural gas swaps are included in the secured hedge facility.

In addition, it will be an event of default under the MGP’s revolving credit facility if it, as our general partner, breaches an obligation governed by the secured hedge facility and the effect of such breach is to cause amounts owing under swap agreements governed by the secured hedge facility to become immediately due and payable.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with U.S. GAAP requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items that are subject to such estimates and assumptions include revenue and expense accruals, depletion and amortization, impairment, fair value of derivative instruments and the probability of forecasted transactions. We summarize our significant accounting policies within our financial statements (See “Item 8: Financial Statements”), included in this report. The critical accounting policies and estimates we have identified are discussed below.

Depletion and Impairment of Long-Lived Assets

Long-Lived Assets. The cost of natural gas and oil properties, less estimated salvage value, is generally depleted on the units-of-production method.

Natural gas and oil properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. A long-lived asset is considered to be impaired when the undiscounted net cash flows expected to be generated by the asset are less than its carrying amount. The undiscounted net cash flows expected to be generated by the asset are based upon our estimates that rely on various assumptions, including natural gas and oil prices, production and operating expenses. Any significant variance in these assumptions could materially affect the estimated net cash flows expected to be generated by the asset. As discussed in General Trends and Outlook within this section, recent increases in natural gas drilling have driven an increase in the supply of natural gas and put a downward pressure on domestic prices. Further declines in natural gas prices may result in additional impairment charges in future periods.


29


 

 

Events or changes in circumstances that would indicate the need for impairment testing include, among other factors: operating losses; unused capacity; market value declines; technological developments resulting in obsolescence; changes in demand for products manufactured by others utilizing our services or for our products; changes in competition and competitive practices; uncertainties associated with the United States and world economies; changes in the expected level of environmental capital, operating or remediation expenditures; and changes in governmental regulations or actions.

During the years ended December 31, 2015 and 2014, we recognized $15,228,700 and $297,500, respectively, of impairments within gas and oil properties, net of offsetting gains from accumulated other comprehensive income of $222,800 and $0, respectively. These impairments related to the carrying amount of these gas and oil properties being in excess of our estimate of their fair value at December 31, 2015 and 2014. The estimate of fair value of these gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.

As a result of the significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on our MGP’s historical experience in determining such values and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.

Fair Value of Financial Instruments

We have established a hierarchy to measure our financial instruments at fair value, which requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

We use a fair value methodology to value the assets and liabilities for our outstanding derivative contracts. Our commodity hedges are calculated based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 fair value measurements.

Liabilities that are required to be measured at fair value on a nonrecurring basis include our asset retirement obligations (“ARO”) that are defined as Level 3. Estimates of the fair value of ARO’s are based on discounted cash flows using numerous estimates, assumptions, and judgments regarding the cost, timing of settlement, our MGP’s credit-adjusted risk-free rate and inflation rates.

Reserve Estimates

Our estimates of proved natural gas, oil and NGL reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures and availability of funds. The accuracy of these reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. We engaged Wright & Company, Inc., an independent third-party reserve engineer, to prepare a report of our proved reserves (See “Item 2: Properties”).


30


 

Any significant variance in the assumptions utilized in the calculation of our reserve estimates could materially affect the estimated quantity of our reserves. As a result, our estimates of proved natural gas and oil reserves are inherently imprecise. Actual future production, natural gas, oil and NGL prices, revenues, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves may vary substantially from our estimates or estimates contained in the reserve reports and may affect our ability to pay distributions. In addition, our proved reserves may be subject to downward or upward revision based upon production history, prevailing natural gas, oil and NGL prices, mechanical difficulties, governmental regulation, and other factors, many of which are beyond our control. Our reserves and their relation to estimated future net cash flows impact the calculation of impairment and depletion of natural gas and oil properties. Generally, an increase or decrease in reserves without a corresponding change in capitalized costs will have a corresponding inverse impact to depletion expense.

We have experienced significant downward revisions of our natural gas and oil reserves volumes and values in 2015 due to the recent significant declines in commodity prices. The proved reserves quantities and future net cash flows were estimated under the SEC’s standardized measure using an unweighted 12-month average pricing based on the gas and oil prices on the first day of each month during the year ended December 31, 2015, including adjustments related to regional price differentials and energy content. The SEC’s standardized measure of reserve quantities and discounted future net cash flows may not represent the fair market value of our gas and oil equivalent reserves due to anticipated future changes in gas and oil commodity prices. Accordingly, such information should not serve as a basis in making any judgement on the potential value of recoverable reserves or in estimating future results of operations.

Asset Retirement Obligations

We recognize and estimate the liability for the plugging and abandonment of our gas and oil wells. The associated asset retirement costs are capitalized as part of the carrying amount of the long lived asset.

The estimated liability is based on our historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using our MGP’s assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. We have no assets legally restricted for purposes of settling asset retirement obligations. Except for our gas and oil properties, we believe that there are no other material retirement obligations associated with tangible long lived assets.

Working Interest

Our Partnership Agreement establishes that revenues and expenses will be allocated to our MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). Our MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

 

 


31


 

 

 

 

 

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

Atlas Resources Public #18-2009 (B) L.P.

We have audited the accompanying balance sheets of Atlas Resources Public #18-2009 (B) L.P. (a Delaware limited partnership) (the “Partnership”) as of December 31, 2015 and 2014, and the related statements of operations, comprehensive income, changes in partners’ capital, and cash flows for each of the two years in the period ended December 31, 2015. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas Resources Public #18-2009 (B) L.P. as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Cleveland, Ohio

April 14, 2016

 


32


 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

BALANCE SHEETS

DECEMBER 31, 2015 AND 2014

 

 

2015

 

  

2014

 

ASSETS

 

 

 

  

 

 

 

Current assets:

 

 

 

  

 

 

 

Cash

$

73,900

 

  

$

-

  

Accounts receivable trade–affiliate

 

451,000

 

  

 

888,500

  

Asset retirement receivable affiliate

 

-

 

 

 

23,700

 

Current portion of derivative assets

 

359,900

 

  

 

429,100

  

Total current assets

 

884,800

 

  

 

1,341,300

  

 

Gas and oil properties, net

 

5,331,700

 

  

 

22,103,100

  

Long-term asset retirement receivable-affiliate

 

69,400

 

 

 

-

 

Long-term derivative assets

 

-

 

  

 

184,500

  

Total assets

$

6,285,900

 

  

$

23,628,900

  

LIABILITIES AND PARTNERS’ CAPITAL

 

 

 

  

 

 

 

Current liabilities:

 

 

 

  

 

 

 

Accounts payable trade-affiliate

$

399,600

 

 

$

399,600

 

Accrued liabilities

 

40,800

 

  

 

30,900

  

Current portion of put premiums payable-affiliate

 

63,300

 

 

 

55,300

 

Total current liabilities

 

503,700

 

  

 

485,800

  

 

Asset retirement obligations

 

1,580,500

 

  

 

1,494,900

  

Long-term put premiums payable-affiliate

 

-

 

  

 

63,200

  

 

Commitments and contingencies (Note 9)

 

 

 

  

 

 

  

 

Partners’ capital:

 

 

 

  

 

 

 

Managing general partner’s interest

 

568,100

 

  

 

2,368,300

  

Limited partners’ capital (12,278 units)

 

3,633,600

 

  

 

18,689,300

  

Accumulated other comprehensive income

 

-

 

  

 

527,400

 

Total partners’ capital

 

4,201,700

 

  

 

21,585,000

  

Total liabilities and partners’ capital

$

6,285,900

 

  

$

23,628,900

  

See accompanying notes to financial statements.

 

 

 

33


 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2015 AND 2014

 

 

 

2015

 

  

2014

 

REVENUES

 

 

 

 

 

 

 

Natural gas, oil and liquids

$

2,383,000

 

 

$

5,546,600

 

Gain on mark-to-market derivatives

 

304,900

 

 

 

-

 

Total revenues

 

2,687,900

 

 

 

5,546,600

 

COSTS AND EXPENSES

 

 

 

 

 

 

 

Production

 

1,689,600

 

 

 

2,268,700

 

Depletion

 

1,316,500

 

 

 

1,959,400

 

Impairment

 

15,228,700

 

 

 

297,500

 

Accretion of asset retirement obligations

 

85,600

 

 

 

40,000

 

General and administrative

 

106,200

 

 

 

104,100

 

Total costs and expenses

 

18,426,600

 

 

 

4,669,700

 

Net (loss) income

$

(15,738,700

)

 

$

876,900

 

Allocation of net (loss) income:

 

 

 

 

 

 

 

Managing general partner

$

(1,566,500

)

 

$

725,100

 

Limited partners

$

(14,172,200

)

 

$

151,800

 

Net (loss) income per limited partnership unit

$

(1,154

)

 

$

12

 

See accompanying notes to financial statements.

 

 

 

34


 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

YEARS ENDED DECEMBER 31, 2015 AND 2014

 

 

2015

 

  

2014

 

Net (loss) income

$

(15,738,700

)

  

$

876,900

 

Other comprehensive (loss) income:

 

 

 

  

 

 

 

Mark-to-market gain on cash flow hedging contracts

 

-

 

  

 

495,100

 

Difference in estimated hedge gains receivable

 

(319,300

)

  

 

(83,400

)

Reclassification adjustment to net (loss) income of mark-to-market gains on cash flow hedges

 

(208,100

)

  

 

221,900

 

Total other comprehensive (loss) income

 

(527,400

)

  

 

633,600

 

Comprehensive (loss) income

$

(16,266,100

)

  

$

1,510,500

 

See accompanying notes to financial statements.

 

 

 

35


 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2015 AND 2014

 

 

Managing
General
Partner

 

  

Limited
Partners

 

  

Accumulated
Other
Comprehensive
Income (Loss)

 

  

Total

 

Balance at December 31, 2013

$

2,924,100

  

  

$

21,961,000

  

  

$

(106,200

)

  

$

24,778,900

  

 

 

 

  

  

 

 

  

  

 

 

  

  

 

 

  

Participation in revenues and costs and expenses:

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Net production revenues

 

1,009,100

 

  

 

2,268,800

 

  

 

-

 

 

 

3,277,900

  

Depletion

 

(193,000

)

 

 

(1,766,400

)

  

 

-

 

 

 

(1,959,400

)

Impairment

 

(50,500

)

  

 

(247,000

)

  

 

-

 

 

 

(297,500

)

Accretion of asset retirement obligations

 

(11,300

)

  

 

(28,700

)

  

 

-

 

 

 

(40,000

)

General and administrative

 

(29,200

)

  

 

(74,900

)

  

 

-

 

 

 

(104,100

)

Net income

 

725,100

 

  

 

151,800

 

  

 

-

 

 

 

876,900

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other comprehensive income

 

-

 

  

 

-

 

  

 

633,600

 

 

 

633,600

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Subordination

 

(565,300

)

  

 

565,300

 

  

 

-

 

 

 

-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions to partners

 

(715,600

)

  

 

(3,988,800

)

  

 

-

 

 

 

(4,704,400

)  

 

Balance at December 31, 2014

 

2,368,300

 

  

 

18,689,300

 

  

 

527,400

 

 

 

21,585,000

  

 

Participation in revenues and costs and expenses:

 

 

 

  

 

 

 

  

 

 

 

 

 

 

 

Net production revenues

 

126,900

 

 

 

566,500

 

 

 

-

 

 

 

693,400

 

Gain on mark-to-market derivatives

 

-

 

 

 

304,900

 

 

 

-

 

 

 

304,900

 

Depletion

 

(128,700

)

 

 

(1,187,800

)

 

 

-

 

 

 

(1,316,500

)

Impairment

 

(1,510,900

)

 

 

(13,717,800

)

 

 

-

 

 

 

(15,228,700

)

Accretion of asset retirement obligations

 

(24,000

)

 

 

(61,600

)

 

 

-

 

 

 

(85,600

)

General and administrative

 

(29,800

)

 

 

(76,400

)

 

 

-

 

 

 

(106,200

)

Net loss

 

(1,566,500

)

 

 

(14,172,200

)

 

 

-

 

 

 

(15,738,700

)

 

Other comprehensive loss

 

-

 

 

 

-

 

 

 

(527,400

)

 

 

(527,400

)

 

Distributions to partners

 

(233,700

)

 

 

(883,500

)

 

 

-

 

 

 

(1,117,200

)

 

Balance at December 31, 2015

$

568,100

 

  

$

3,663,600

 

  

$

-

 

 

$

4,201,700

 

See accompanying notes to financial statements.

 

 

 

36


 

 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2015 AND 2014

 

 

2015

 

  

2014

 

Cash flows from operating activities:

 

 

 

  

 

 

 

Net (loss) income

$

(15,738,700

)

  

$

876,900

 

Adjustments to reconcile net (loss) income to net cash provided by operating activities:

 

 

 

  

 

 

 

Depletion

 

1,316,500

 

  

 

1,959,400

  

Impairment

 

15,228,700

 

  

 

297,500

  

Non-cash (gain) loss on derivative value

 

(106,100

)

  

 

183,300

 

Accretion of asset retirement obligations

 

85,600

 

  

 

40,000

  

Changes in operating assets and liabilities:

 

 

 

  

 

 

 

Decrease in accounts receivable trade-affiliate

 

437,500

 

  

 

665,700

 

Increase in asset retirement receivable-affiliate

 

(45,700

)

 

 

(23,700

)

Decrease in accounts payable trade-affiliate

 

-

 

 

 

(16,000

)

Increase (decrease) in accrued liabilities

 

9,900

 

  

 

(6,400

)

Net cash provided by operating activities

 

1,187,700

 

  

 

3,976,700

  

 

Cash flows from investing activities:

 

 

 

  

 

 

 

Purchase of tangible equipment

 

-

 

  

 

(4,500

)

Proceeds from sale of tangible equipment

 

3,400

 

 

 

9,400

 

Proceeds from sale of oil and gas properties

 

-

 

 

 

369,000

 

Net cash provided by investing activities

 

3,400

 

  

 

373,900

 

 

Cash flows from financing activities:

 

 

 

  

 

 

 

Distributions to partners

 

(1,117,200

)

  

 

(4,704,400

)

Net cash used in financing activities

 

(1,117,200

)

  

 

(4,704,400

)

 

Net change in cash

 

73,900

 

  

 

(353,800

)

Cash at beginning of year

 

-

 

  

 

353,800

 

Cash at end of year

$

73,900

 

  

$

-

 

 

Supplemental schedule of non-cash investing and financing activities:

 

 

 

  

 

 

 

 

 

 

 

 

 

 

 

Asset retirement obligations revision

$

-

 

  

$

779,600

 

See accompanying notes to financial statements.

 

 

 

37


 

ATLAS RESOURCES PUBLIC #18-2009 (B) L.P.

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2015 AND 2014

 

NOTE 1—BASIS OF PRESENTATION

Atlas Resources Public #18-2009 (B) L.P. (the “Partnership”) is a Delaware limited partnership, formed on April 8, 2008 with Atlas Resources, LLC serving as its Managing General Partner and Operator (“Atlas Resources” or the “MGP”). Atlas Resources is an indirect subsidiary of Atlas Resource Partners, L.P. (“ARP”) (NYSE: ARP).

 

On February 27, 2015, the MGP’s ultimate parent, Atlas Energy, L.P. (“Atlas Energy”), which was a publicly traded master-limited partnership, was acquired by Targa Resources Corp. and distributed to Atlas Energy’s unitholders 100% of the limited liability company interests in ARP’s general partner, Atlas Energy Group, LLC (“Atlas Energy Group”; OTCQX: ATLS).  Atlas Energy Group became a separate, publicly traded company and the ultimate parent of the MGP as a result of the distribution. Following the distribution, Atlas Energy Group continues to manage ARP’s operations and activities through its ownership of the ARP’s general partner interest.

The Partnership has drilled and currently operates wells located in Pennsylvania, Tennessee and Indiana. The Partnership has no employees and relies on the MGP for management, which in turn, relies on its parent company, Atlas Energy Group (February 27, 2015 and prior, Atlas Energy), for administrative services.

The Partnership’s operating cash flows are generated from its wells, which produce natural gas and oil. Produced natural gas and oil is then delivered to market through affiliated and/or third-party gas gathering systems. The Partnership intends to produce its wells until they are depleted or become uneconomical to produce at which time they will be plugged and abandoned or sold. The Partnership does not expect to drill additional wells and expects no additional funds will be required for drilling.

The economic viability of the Partnership’s production is based on a variety of factors including proved developed reserves that it can expect to recover through existing wells with existing equipment and operating methods or in which the cost of additional required extraction equipment is relatively minor compared to the cost of a new well; and through currently installed extraction equipment and related infrastructure which is operational at the time of the reserves estimate (if the extraction is by means not involving drilling, completing or reworking a well). There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues.

The prices at which the Partnership’s natural gas and oil will be sold are uncertain and the Partnership is not guaranteed a specific natural gas price for the sale of its natural gas production. Changes in natural gas and oil prices have a significant impact on the Partnership’s cash flow and the value of its reserves. Lower natural gas and oil prices may not only decrease the Partnership’s revenues, but also may reduce the amount of natural gas and oil that the Partnership can produce economically.

Liquidity and Capital Resources

The Partnership is generally limited to the amount of funds generated by the cash flow from its operations to fund its obligations and make distributions, if any, to its partners.

The natural gas, oil and natural gas liquids commodity price markets have suffered significant declines during the fourth quarter of 2014 and throughout 2015.  The extreme ongoing volatility in the energy industry and commodity prices will likely continue to impact the Partnership’s outlook. The Partnership has experienced downward revisions of its natural gas and oil reserves volumes and values due to the significant declines in commodity prices. The MGP continues to implement various cost saving measures to reduce the Partnership’s operating and general and administrative costs, including renegotiating contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs. The MGP will continue to be opportunistic and aggressive in managing the Partnership’s cost structure and, in turn, liquidity to meet its operating needs. To the extent commodity prices remain low or decline further, or the Partnership experiences other disruptions in the industry, the Partnership’s ability to fund its operations and make distributions may be further impacted, and could result in the MGP’s decision to liquidate the Partnership’s operations.


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Historically, there has been no need to borrow funds from the MGP to fund operations as the cash flow from the Partnership’s operations have been adequate to fund its obligations and distributions to its partners. However, the recent significant declines in commodity prices have challenged the Partnership’s ability to fund its operations and may make it uneconomical for the Partnership to produce its wells until they are depleted, as the Partnership originally intended. Accordingly, the MGP determined that there is substantial doubt about the Partnership’s ability to continue as a going concern. The MGP intends, as necessary, to continue the Partnership’s operations and to fund the Partnership’s obligations for at least the next twelve months. The MGP has concluded that such undertaking is sufficient to alleviate the doubt as to the Partnership’s ability to continue as a going concern

If, however, the MGP were to decide to liquidate our operations, the liquidation valuation of the Partnership’s assets and liabilities would be determined by an independent expert. It is possible that based on such determination, we would not be able to make any liquidation distributions to our limited partners. A liquidation could result in the transfer of the post-liquidation assets and liabilities of the Partnership to the MGP and would occur without any further contributions from or distributions to the limited partners.

 

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the Partnership’s financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s financial statements, as well as the reported amounts of revenue and costs and expenses during the reporting periods. The Partnership’s financial statements are based on a number of significant estimates, including revenue and expense accruals, depletion, depreciation and amortization, asset impairments, fair value of derivative instruments, and the probability of forecasted transactions. The oil and gas industry principally conducts its business by processing actual transactions as many as 60 days after the month of delivery.  Consequently, the most recent two months’ financial results were recorded using estimated volumes and contract market prices (see “Revenue Recognition”). Actual results could differ from those estimates.  

Receivables

Accounts receivable trade-affiliate on the balance sheets consist solely of the trade accounts receivable associated with the Partnership’s operations. In evaluating the realizability of its accounts receivable, the MGP performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by management’s review of the credit information. The Partnership extends credit on sales on an unsecured basis to many of their customers. At December 31, 2015 and 2014, the Partnership had recorded no allowance for uncollectible accounts receivable on its balance sheets.

 

Asset retirement receivable – affiliate on the balance sheets consist solely of the net amount withheld from distributions for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the Partnerships wells less any amounts used for the plugging and abandonment of the Partnership’s wells. As amounts are withheld, they are paid to the MGP and held until the Partnerships wells are plugged and abandoned, at which time, the funds are used to cover the actual expenditures incurred. The total amount withheld from distributions will not exceed the MGP’s estimate of the costs to plug and abandon the Partnership’s wells.

 

The following is a reconciliation of the Partnership’s asset retirement receivable – affiliate for the years indicated:

 

 

December 31,

 

 

2015

 

 

2014

 

Asset retirement receivable – affiliate, beginning of year

$

23,700

 

 

$

-

 

Asset retirement estimates withheld

 

45,700

 

 

 

23,700

 

Asset retirement receivable –affiliate, end of year

$

69,400

 

 

$

23,700

 

 


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Gas and Oil Properties

Gas and oil properties are stated at cost. Maintenance and repairs that generally do not extend the useful life of an asset for two years or more through the replacement of critical components are expensed as incurred. Major renewals and improvements that generally extend the useful life of an asset for two years or more through the replacement of critical components are capitalized.

The Partnership follows the successful efforts method of accounting for gas and oil producing activities. Oil and natural gas liquids are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel of oil to six mcf of natural gas.

The Partnership’s depletion expense is determined on a field-by-field basis using the units-of-production method. Depletion rates for lease, well and related equipment costs are based on proved developed reserves associated with each field. Depletion rates are determined based on reserve quantity estimates and the capitalized cost of developed producing properties.

Upon the sale or retirement of a complete field of a proved property, the Partnership eliminates the cost from the property accounts and the resultant gain or loss is reclassified to the Partnership’s statements of operations. Upon the sale or retirement of an individual well, the Partnership reclassifies the costs associated with the well and credits the proceeds to accumulated depletion and impairment within its balance sheets.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount of that asset to its estimated fair value if such carrying amount exceeds the fair value.

The review of the Partnership’s gas and oil properties is done on a field-by-field basis by determining if the historical cost of proved properties less the applicable accumulated depletion and impairment is less than the estimated expected undiscounted future cash flows including salvage. The expected future cash flows are estimated based on the Partnership’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of the production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon current contracts in place, adjusted for basis differentials and market related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value and the carrying value of the assets.

The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results.

In addition, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information which could cause the assumptions to be modified. The Partnership cannot predict what reserve revisions may be required in future periods.


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Derivative Instruments

The Partnership’s MGP enters into certain financial contracts to manage the Partnership’s exposure to movement in commodity prices (See Note 6). The derivative instruments recorded on the balance sheets were measured as either an asset or liability at fair value. Changes in a derivative instrument’s fair value are recognized currently in the Partnership’s statements of operations unless specific hedge accounting criteria are met. On January 1, 2015, the Partnership discontinued hedge accounting through de-designation for all of its existing commodity derivatives which were qualified as hedges. As such, subsequent changes in fair value after December 31, 2014 of these derivatives are recognized immediately within gain (loss) on mark-to-market derivatives in the Partnership’s statements of operations, while the fair values of the instruments recorded in accumulated other comprehensive income as of December 31, 2014 will be reclassified to the statements of operations in the periods in which those respective derivative contracts settle. Prior to discontinuance of hedge accounting, the fair value of these commodity derivative instruments was recognized in accumulated other comprehensive income (loss) within partners’ (deficit) capital on the Partnership’s balance sheets and reclassified to the Partnership’s statements of operations at the time the originally hedged physical transactions affected earnings.

Asset Retirement Obligations

The Partnership recognizes an estimated liability for the plugging and abandonment of its gas and oil wells and related facilities (See Note 5). The Partnership recognizes a liability for its future asset retirement obligations in the current period if a reasonable estimate of the fair value of that liability can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The Partnership also considers the estimated salvage value in the calculation of depletion.

Income Taxes

The Partnership is not subject to U.S. federal and most state income taxes. The partners of the Partnership are liable for income tax in regard to their distributive share of the Partnership’s taxable income. Such taxable income may vary substantially from net income reported in the financial statements. The federal and state income taxes related to the Partnership were immaterial to the financial statements and are recorded in pre-tax income on a current basis only. Accordingly, no federal or state deferred income tax has been provided for in the financial statements.

The Partnership evaluates tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than-not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its financial statements that would not meet this threshold. The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions, when and if they become applicable. However, the Partnership has not recognized any potential interest or penalties in its financial statements as of December 31, 2015 and 2014.

The Partnership files Partnership Returns of Income in the U.S. and various state jurisdictions. With few exceptions, the Partnership is no longer subject to income tax examinations by major tax authorities for years prior to 2011. The Partnership is not currently being examined by any jurisdiction and is not aware of any potential examinations as of December 31, 2015.

Environmental Matters

The Partnership is subject to various federal, state, and local laws and regulations relating to the protection of the environment. Management has established procedures for the ongoing evaluation of the Partnership’s operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Partnership maintains insurance which may cover in whole or in part certain environmental expenditures. The Partnership had no environmental matters requiring specific disclosure or requiring the recognition of a liability for the years ended December 31, 2015 and 2014.


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Concentration of Credit Risk

The Partnership sells natural gas, crude oil, and NGLs under contracts to various purchasers in the normal course of business. For the year ended December 31, 2015, the Partnership had two customers that individually accounted for approximately 81% and 13% of the Partnership’s natural gas, oil, and NGL combined revenues, excluding the impact of all financial derivative activity. For the year ended December 31, 2014, the Partnership had one customer that individually accounted for approximately 96% of the Partnership’s natural gas, oil, and NGL combined revenues, excluding the impact of all financial derivative activity.

Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. There were no deposits over the insurance limit as of December 31, 2015 and December 31, 2014.

Revenue Recognition

The Partnership generally sells natural gas, crude oil, and NGLs at prevailing market prices. Generally, the Partnership’s sales contracts are based on pricing provisions that are tied to a market index, with certain fixed adjustments based on proximity to gathering and transmission lines and the quality of its natural gas. Generally, the market index is fixed two business days prior to the commencement of the production month. Revenue and the related accounts receivable are recognized when produced quantities are delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Revenues from the production of natural gas, crude oil, and NGLs, in which the Partnership has an interest with other producers, are recognized on the basis of its percentage ownership of the working interest and/or overriding royalty.

The MGP and its affiliates perform all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable trade-affiliate on the Partnership’s balance sheets includes the net production revenues due from the MGP. The Partnership accrues unbilled revenue due to timing differences between the delivery of natural gas, NGLs, crude oil and condensate, and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Partnership’s records and management estimates of the related commodity sales and transportation and compression fees which are, in turn, based upon applicable product prices (See “-Use of Estimates”). The Partnership had unbilled revenues at December 31, 2015 and 2014 of $327,600 and $589,400, respectively, which were included in accounts receivable trade-affiliate within the Partnership’s balance sheets.

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net income (loss). These changes, other than net income (loss), are referred to as “other comprehensive income (loss)” on the Partnership’s financial statements and, at December 31, 2015, only include changes in the fair value of unsettled derivative contracts which, prior to January 1, 2015, were accounted for as cash flow hedges (See Note 4). The Partnership does not have any other type of transaction which would be included within other comprehensive income (loss).

Recently Issued Accounting Standards

In August 2014, the FASB updated the accounting guidance related to the evaluation of whether there is substantial doubt about an entity’s ability to continue as a going concern. The updated accounting guidance requires an entity’s management to evaluate whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year from the date the financial statements are issued and provide footnote disclosures, if necessary.  The updated guidance is effective as of January 1, 2017 and the Partnership is currently in the process of determining the impact of providing the enhanced disclosures, as applicable, within its financial statements. 

In May 2014, the FASB updated the accounting guidance related to revenue recognition. The updated accounting guidance provides a single, contract-based revenue recognition model to help improve financial reporting by providing clearer guidance on when an entity should recognize revenue, and by reducing the number of standards to which an entity has to refer. In July 2015, the FASB voted to defer the effective date by one year to December 15, 2017 for annual reporting periods beginning after that date. The updated accounting guidance provides companies with alternative methods of adoption. The Partnership is currently in the process of determining the impact that the updated accounting guidance will have on its financial statements and its method of adoption.


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NOTE 3—PARTICIPATION IN REVENUES AND COSTS

Working Interest

The Partnership Agreement establishes that revenues and expenses will be allocated to the MGP and limited partners based on their ratio of capital contributions to total contributions (“working interest”). The MGP is also provided an additional working interest of 10% as provided in the Partnership Agreement. Due to the time necessary to complete drilling operations and accumulate all drilling costs, estimated working interest percentage ownership rates are utilized to allocate revenues and expense until the wells are completely drilled and turned on-line into production. Once the wells are completed, the final working interest ownership of the partners is determined and any previously allocated revenues based on the estimated working interest percentage ownership are adjusted to conform to the final working interest percentage ownership.

The MGP and the limited partners generally participated in revenues and costs in the following manner:

 

 

Managing
General
Partner

 

 

Limited
Partners

 

Organization and offering costs

 

100%

 

 

 

0%

 

Lease costs

 

100%

 

 

 

0%

 

Intangible drilling costs

 

5%

 

 

 

95%

 

Tangible equipment costs

 

29%

 

 

 

71%

 

Revenues (1)

 

28%

 

 

 

72%

 

Operating costs, administrative costs, direct and all other costs (2)

 

28%

 

 

 

72%

 

 

 

 

 

 

 

 

 

 

 

(1)

Subject to the MGP’s subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the MGP will receive an additional 10% of the partnership revenues.

 

(2)

These costs will be charged to the partners in the same ratio as the related production revenues are credited.

 

NOTE 4PROPERTY, PLANT AND EQUIPMENT

The following is a summary of natural gas and oil properties at the dates indicated:

 

 

December 31,

 

 

2015

 

  

2014

 

Proved properties:

 

 

 

  

 

 

 

Leasehold interests

$

906,300

 

  

$

906,300

 

Wells and related equipment

 

128,077,100

 

  

 

128,080,500

 

Total natural gas and oil properties

 

128,983,400

 

  

 

128,986,800

 

Accumulated depletion and impairment

 

(123,651,700

)

  

 

(106,883,700

)

Gas and oil properties, net

$

5,331,700

 

  

$

22,103,100

 

The Partnership recorded depletion expense on natural gas and oil properties of $1,316,500 and $1,959,400 for the years ended December 31, 2015 and 2014, respectively.

During the years ended December 31, 2015 and 2014, the Partnership recognized $15,451,500 and $297,500, respectively, of impairments related to natural gas and oil properties on its balance sheets. These impairments related to the carrying amount of these natural gas and oil properties being in excess of the Partnership’s estimate of their fair value at December 31, 2015 and 2014. The estimate of fair value of these natural gas and oil properties was impacted by, among other factors, the deterioration of natural gas and oil prices at the date of measurement.

As a result of the recent significant declines in commodity prices and associated recorded impairment charges, remaining net book value of gas and oil properties on our balance sheet at December 31, 2015 was primarily related to the estimated salvage value of such properties. The estimated salvage values were based on the MGP’s historical experience in determining such values and were discounted based on the remaining lives of those wells using an assumed credit adjusted risk-free interest rate.


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NOTE 5—ASSET RETIREMENT OBLIGATIONS

The estimated liability for asset retirement obligations was based on the MGP’s historical experience in plugging and abandoning wells, the estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The liability was discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. The Partnership has no assets legally restricted for purposes of settling asset retirement obligations. Except for its gas and oil properties, the Partnership determined that there were no other material retirement obligations associated with tangible long-lived assets.

The MGP’s historical practice and continued intention is to retain distributions from the limited partners as the wells within the Partnership near the end of their useful life. On a partnership-by-partnership basis, the MGP assesses its right to withhold amounts related to plugging and abandonment costs based on several factors including commodity price trends, the natural decline in the production of the wells and current and future costs. Generally, the MGP’s intention is to retain distributions from the limited partners as the fair value of the future cash flows of the limited partners’ interest approaches the fair value of the future plugging and abandonment cost. Upon the MGP’s decision to retain all future distributions to the limited partners of the Partnership, the MGP will assume the related asset retirement obligations of the limited partners. As of December 31, 2015, the MGP withheld $69,400 of net production revenue for future plugging and abandonment costs.

A reconciliation of the Partnership’s asset retirement obligation liability for well plugging and abandonment costs for the periods indicated is as follows:

 

 

Years Ended December 31,

 

 

2015

 

  

2014

 

Beginning of year

$

1,494,900

 

 

$

675,300

 

Accretion expense

 

85,600

 

 

 

40,000

 

Revisions

 

-

 

 

 

779,600

 

End of year

$

1,580,500

 

 

$

1,494,900

 

 

 

NOTE 6—DERIVATIVE INSTRUMENTS

 

The MGP, on behalf of the Partnership, uses a number of different derivative instruments, principally swaps, and put options, in connection with the Partnership’s commodity price risk management activities. Management uses financial instruments to hedge forecasted commodity sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying commodities are sold. Under commodity-based swap agreements, the Partnership receives or pays a fixed price and receives or remits a floating price based on certain indices for the relevant contract period. To manage the risk of regional commodity price differences, the Partnership occasionally enters into basis swaps. Basis swaps are contractual arrangements that guarantee a price differential for a commodity from a specified delivery point price and the comparable national exchange price. For natural gas basis swaps, which have negative differentials to NYMEX, the Partnership receives or pays a payment from the counterparty if the price differential to NYMEX is greater or less than the stated terms of the contract. Commodity-based put option instruments are contractual agreements that require the payment of a premium and grant the purchaser of the put option the right, but not the obligation, to receive the difference between a fixed, or strike price, and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. The put option instrument sets a floor price for commodity sales being hedged.


44


 

The Partnership enters into derivative contracts with various financial institutions, utilizing master contracts based upon the standards set by the International Swaps and Derivatives Association, Inc. These contracts allow for rights of offset at the time of settlement of the derivatives. Due to the right of offset, derivatives are recorded on the Partnership’s balance sheets as assets or liabilities at fair value on the basis of the net exposure to each counterparty. Potential credit risk adjustments are also analyzed based upon the net exposure to each counterparty. Premiums paid for purchased options are recorded on the Partnership’s balance sheets as the initial value of the options. The Partnership reflected net derivative assets on its balance sheets of $359,900 and $613,600 at December 31, 2015 and 2014, respectively.

At December 31, 2015, the Partnership had the following commodity derivatives:

Natural Gas Fixed Price Swaps—Limited Partners

 

Production Period Ending
December 31,

  

Volumes
(MMBtu) (1)

 

  

Average
Fixed Price
(per MMBtu) (1)

 

  

Fair Value
Asset (2)

 

2016

  

 

114,500

  

  

$

4.46

  

  

$

222,900

 

 

Natural Gas Put Options—Limited Partners

 

Production Period Ending
December 31,

  

Volumes
(MMBtu) (1)

 

  

Average
Fixed Price
(per MMBtu) (1)

 

  

Fair Value
Asset (2)

 

2016

  

 

82,400

  

  

$

4.15

  

  

$

137,000

  

 

 

 

Limited Partner’s Commodity Derivatives, net

 

 

 

359,900

 

 

 

 

(1)

“MMBtu” represents million British Thermal Units.

 

(2)

Fair value based on forward NYMEX natural gas prices, as applicable.

 

The following table summarizes the gains or losses recognized within the statements of operations for derivative instruments previously designated as cash flow hedges for the periods indicated:

 

 

Years Ended
December 31,

 

 

 

2015

 

 

2014

 

 

(Loss) gain reclassified from accumulated other comprehensive income into natural gas, oil and liquids revenues

$

208,100

 

 

$

(221,900

)

 

Gain subsequent to hedge accounting recognized in gain on mark-to-market derivatives

$

304,900

 

 

$

-

 

 


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The MGP has a secured hedge facility agreement with a syndicate of banks under which the Partnership has the ability to enter into derivative contracts to manage its exposure to commodity price movements. Under the MGP’s revolving credit facility the Partnership is required to utilize this secured hedge facility for future commodity risk management activity. The Partnership’s obligations under the facility are secured by mortgages on its gas and oil properties and first priority security interests in substantially all of its assets and by a guarantee of the MGP. The MGP administers the commodity price risk management activity for the Partnership under the secured hedge facility. The secured hedge facility agreement contains covenants that limit the Partnership’s ability to incur indebtedness, grant liens, make loans or investments, make distributions if a default under the secured hedge facility agreement exists or would result from the distribution, merge into or consolidate with other persons, enter into commodity or interest rate swap agreements that do not conform to specified terms or that exceed specified amounts, or engage in certain asset dispositions including a sale of all or substantially all of its assets. As of December 31, 2015, only the Partnership’s natural gas swaps are included in the secured hedge facility.

Put Premiums Payable

During June 2012, a premium (“put premium”) was paid to purchase the contracts and will be allocated to natural gas production revenues generated over the contractual term of the purchased hedging instruments. At December 31, 2015 and 2014, the put premiums were recorded as short-term payables to affiliate, of $63,300 and $55,300 respectively, and long-term payables to affiliate of $0 and $63,200, respectively.

 

NOTE 7—FAIR VALUE OF FINANCIAL INSTRUMENTS

The Partnership has established a hierarchy to measure its financial instruments at fair value, which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect the Partnership’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The hierarchy defines three levels of inputs that may be used to measure fair value:

Level 1 – Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date.

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market data for substantially the entire contractual term of the asset or liability.

Level 3 – Unobservable inputs that reflect the entity’s own assumptions about the assumptions market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership uses a market approach fair value methodology to value the assets and liabilities for its outstanding derivative contracts (See Note 6). The Partnership manages and reports the derivative assets and liabilities on the basis of its net exposure to market risks and credit risks by counterparty. The Partnership’s commodity derivative contracts are valued based on observable market data related to the change in price of the underlying commodity and are therefore defined as Level 2 assets and liabilities within the same class of nature and risk. The fair values of these derivative instruments are calculated by utilizing commodity indices, quoted prices for futures and options contracts traded on open markets that coincide with the underlying commodity, expiration period, strike price (if applicable) and the pricing formula utilized in the derivative instrument.


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Information for assets and liabilities measured at fair value was as follows:

 

 

  

Level 1

 

  

Level 2

 

  

Level 3

 

  

Total

 

As of December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

Derivative assets, gross

  

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

Commodity swaps

  

$

-

 

 

$

222,900

 

  

$

-

 

 

$

222,900

 

Commodity puts

  

 

-

 

 

 

137,000

 

  

 

-

 

 

 

137,000

 

Total derivative assets, gross

  

$

-

 

 

$

359,900

 

  

$

-

 

 

$

359,900

 

 

As of December 31, 2014

  

 

 

  

 

 

  

 

 

  

 

 

Derivative assets, gross

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Commodity swaps

  

$

-

  

  

$

455,400

 

  

$

-

  

  

$

455,400

 

Commodity puts

  

 

-

  

  

 

158,200

 

  

 

-

  

  

 

158,200